Compact fluid disposal system and method for surface well testing

ABSTRACT

A compact fluid disposal and surface well testing system and method, including a multiphase meter for flow-metering and sampling of a received oil/gas/water stream and generating flow information for the received oil/gas/water stream; a compact gas/liquid splitter coupled to the multiphase meter and configured for generating a gas rich stream, and a liquid rich stream from the oil/gas/water stream based on the flow information from the multiphase meter; and a free water knock out (FWKO)/holding tank coupled to the compact gas/liquid splitter for receiving the liquid rich stream from the compact gas/liquid splitter and degassing the liquid rich stream and performing oil/water separation on the liquid rich stream.

CROSS REFERENCE TO RELATED DOCUMENTS

The present invention claims benefit of priority to U.S. Provisional Patent Application Ser. No. 61/016,542 of Francis ALLOUCHE, entitled “COMPACT FLUID DISPOSAL SYSTEM AND METHOD FOR SURFACE WELL TESTING,” filed on Dec. 24, 2007, the entire content of which is hereby incorporated by reference herein.

BACKGROUND OF THE INVENTION

1. Field of the Invention

The present invention generally relates to well testing, and more particularly to a compact fluid disposal system and method for surface well testing.

2. Discussion of the Background

In surface well testing, the three main objectives are to measure the volumetric flow-rate of individual phases, obtain samples and determine characteristics of the main fluids, and disposal off the effluents. In recent years, metering technology has been developed to provide individual flow-rates without needing any separation, thanks to the use of multiphase meters that can measure the flow rate of the oil, gas and water in a oil well effluent without the need for separation. However, there is still no available solution to disposal of the effluents without preliminary separation. For example, a separator is still required to separate liquid from gas to burn oil and flare gas, respectively. The separator is also needed when handling the clean-up phase to extract water from oil, when the resulting liquid is not burnable.

Accordingly, even in view of advances in the background art systems, there is still a need for a compact fluid disposal system and method for surface well testing.

SUMMARY OF THE INVENTION

The above and other needs and problems are addressed by the exemplary embodiments of the present invention, which provide a method and system for compact fluid disposal and surface well testing. Accordingly, in exemplary embodiments a novel system and method for fluid disposal for surface well testing applications are provided. An exemplary global surface platform employs a multiphase meter for metering and fluid sampling purposes. Downstream of the multiphase meter is a disposal system made up of a compact high pressure gas/liquid splitter and a combined low pressure free water knock out (FWKO)/holding tank. The exemplary platform can be used for the beginning of a well clean up phase, for clean up of a well in development, and to stabilize flow of a well.

Accordingly, in an exemplary aspect of the present invention there is provided a compact fluid disposal and surface well testing system. The system includes a multiphase meter for flow-metering and sampling of a received oil/gas/water stream and generating flow information for the received oil/gas/water stream; a compact gas/liquid splitter coupled to the multiphase meter and configured for generating a gas rich stream, and a liquid rich stream from the oil/gas/water stream based on the flow information from the multiphase meter; and a free water knock out (FWKO)/holding tank coupled to the compact gas/liquid splitter for receiving the liquid rich stream from the compact gas/liquid splitter and degassing the liquid rich stream and performing oil/water separation on the liquid rich stream.

In another exemplary aspect of the invention, a method is provided for a fluid disposal and surface well testing system, which may be a compact system. The method includes flow-metering and sampling a received oil/gas/water stream and generating flow information for the received oil/gas/water stream with a multiphase meter; generating a gas rich stream, and a liquid rich stream from the oil/gas/water stream based on the flow information from the multiphase meter with a compact gas/liquid splitter coupled to the multiphase meter; and receiving the liquid rich stream from the compact gas/liquid splitter and degassing the liquid rich stream and performing oil/water separation on the liquid rich stream with a free water knock out (FWKO)/holding tank coupled to the compact gas/liquid splitter.

Still other aspects, features, and advantages of the present invention are readily apparent from the following detailed description, by illustrating a number of exemplary embodiments and implementations, including the best mode contemplated for carrying out the present invention. The present invention is also capable of other and different embodiments, and its several details can be modified in various respects, all without departing from the spirit and scope of the present invention. Accordingly, the drawings and descriptions are to be regarded as illustrative in nature, and not as restrictive.

BRIEF DESCRIPTION OF THE DRAWINGS

The embodiments of the present invention are illustrated by way of example, and not by way of limitation, in the figures of the accompanying drawings and in which like reference numerals refer to similar elements and in which:

FIG. 1 illustrates a typical scenario of gas and liquid flow-rate evolution against time for a well in development;

FIG. 2 illustrates a background art surface testing platform based on a horizontal gravity separator;

FIG. 3 illustrates a background art flow mixer used as a slug catcher;

FIG. 4 illustrates typical performance characteristics of the flow mixer of FIG. 3;

FIG. 5 illustrates a background art vortex separator;

FIGS. 6-8 illustrate a background art low current-high voltage electro-coalescer; and

FIGS. 9-17 illustrate an exemplary compact fluid disposal system and method for surface well testing, according to the present invention.

DETAILED DESCRIPTION

Various embodiments and aspects of the invention will now be described in detail with reference to the accompanying figures. Still other aspects, features, and advantages of the present invention are readily apparent from the entire description thereof, including the figures, which illustrate a number of exemplary embodiments and implementations. Furthermore, the terminology and phraseology used herein is solely used for descriptive purposes and should not be construed as limiting in scope. Language such as “including,” “comprising,” “having,” “containing,” or “involving,” and variations thereof, is intended to be broad and encompass the subject matter listed thereafter, equivalents, and additional subject matter not recited.

During a well clean-up phase, liquid initially is placed in temporary or permanent completion and a rate hole comes up at the surface (referred to as Phase 1). For a well in development, it is not rare to recover a large volume of completion fluids, which are non-hydrocarbon fluids or a mixture of fluids which are not burnable (referred to as Phase 2). The end of the clean-up is reached when the gas-oil ratio (GOR) is stabilizing (referred to as Phase 3). At this time the water flow-rate usually drops to zero (or at least to a low flow-rate). Accordingly, FIG. 1 illustrates a typical scenario of gas and liquid flow-rate evolution against time for a well in development and for which a long cleanup phase, producing large volume of non-hydrocarbons fluids at surface, is needed before starting the usual flow-periods.

FIG. 2 illustrates a background art surface testing platform based on a horizontal gravity separator. In FIG. 2, a surge tank is usually made of two separate compartments. One is used as a tank holder for mud or any fluids recovered at the very beginning of the clean-up. These fluids need to be flashed and degassed through that tank to be eventually dumped to rig tanks that can be offshore. The second compartment is traditionally used as a buffer when the oil flow-rate is very low during the transition zone between the end of the clean-up and the beginning of the flow-period, but also for calibration of oil flow-meters. Such calibration is referred to as “combined meter factor,” including both shrinkage and meter calibration against oil density. In some applications, a steam exchanger is often used to enhance separation, but also to prevent gas hydrate formation at the choke level when there is some water present.

Background art separation systems include centrifugal systems that employ internal or external power and that are mainly designed to separate oil from water with relatively high efficiency. A flow mixer is a purely static device, including a tank into which the multiphase flow is fed. Most of the dense part of the fluid is drained from the bottom of the tank through an ejector, while the least dense part is drained from the top and directed via a pipe back to the ejector, where it is mixed with the dense part of the fluid, according to the ejection ratio. FIG. 3 shows an existing flow mixer used as a slug catcher.

The performance of such a flow mixer can easily be adopted to fit various requirements. FIG. 4 illustrates typical performance characteristics of the flow mixer of FIG. 3. In FIG. 4, the typical performance characteristics of the flow mixer over time are illustrated by simulating a square-wave hold-up pattern 402 at the inlet to the unit and with outlet gas volume fraction (GVF) 404 and liquid levels 406 also plotted.

FIG. 5 shows a background art continuous flow separator that simultaneously separates liquid/liquid, liquid/solid and liquid/liquid/solid mixtures flowing through the separator at high flow rates. In FIG. 5, the separator is a continuous flow turbo machine that generates a strong centrifugal action or vortex capable of separating light and heavy liquids, such as oil and water, or any other combination of liquids and solids, at extremely high flow rates. This separator accomplishes this separation through the creation of a strong vortex in the flow, as the fluid flows through the machine. In oil and water mixtures, this vortex causes the heavier elements (e.g., water) to gravitate to the outside of the flow and the lighter elements (e.g., oil) to move to the center, which forms an inner core. If solids are present and they are heavier than the liquid, they will be drawn to the outside of the flow and follow the walls of the exit pipe or tube. The stream exiting the machine will be divided, as shown in FIG. 5, into two separate streams of the heavier liquid (e.g., water) and lighter liquid (e.g., oil). As a result, separation is achieved.

A vortex separator, while achieving separation, also acts as its own pump, moving the fluid mixture through the machine. The open design of the impeller blades makes the separator virtually non-clogable. The centrifugal force generated by causing the flow to rotate rapidly in a vortex about the centerline of the impeller is the fundamental separation mechanism for a vortex separator. A vortex separator is energy self-sufficient and provides its own motive force.

FIGS. 6-8 illustrate a background art low current-high voltage electrostatic coalescer to make oil-water separation more efficient and cost-effective, and which is especially designed to improve separation and the quality of the produced oil and water. Separators often experience problems with emulsions and capacity limits. An electrostatic coalescer (which may also be herein referred to as “electro-coalescer”) can enhance the speed and efficiency of the separation process, by forcing small water droplets in the oil continuous phase to merge and form larger, faster sedimenting drops. However, this technology has so far been unavailable for the turbulent conditions in the inlet separator.

The use of an electrostatic coalescer greatly improves both the oil and produced water quality, as shown in FIGS. 7-8. In addition, the use of an electrostatic coalescer can provide increased ability to separate heavy oil, improve produced water quality, increase production, reduce emulsion breaker consumption, improve process control, and reduce heating requirements.

Generally, the exemplary embodiments are directed to a novel system and method for fluid disposal for surface well testing applications. An exemplary surface platform employs a multiphase meter for metering and fluid sampling purposes including determining flow trends. Downstream of the multiphase meter is a disposal system made up of a compact high pressure gas/liquid splitter and a combined low pressure free water knock out FWKO/holding tank, which will be described in more detail hereinafter.

The exemplary platform can be used for the beginning of a well clean up phase, wherein effluent is directly sent to a holding compartment of the FWKO/holding tank for degassing purposes or flows through to the compact gas/liquid splitter to handle gas pockets.

The exemplary platform also can be used for clean up of a well in development, wherein effluent is pre-separated through the compact gas/liquid splitter, a liquid rich stream is sent to an oil/water separation compartment of the FWKO/holding tank for degassing and oil/water separation, water is extracted from a bottom of the FWKO/holding tank for disposal, and separated oil is pumped and burned with an oil burner (e.g., an EVERGREEN available from Schlumberger), and the gas rich stream is sent to a wet gas flare.

The exemplary platform can additionally be used to stabilize flow of a well, wherein the liquid rich stream includes less than 25% of water so that a resulting liquid is directly burnable through the oil burner and the gas rich stream is sent to the wet gas flare. The exemplary platform, advantageously, enables a global foot print reduction between 40-60%, as compared to background art systems.

In terms of disposal, the flow envelope is about the same, and potentially greater than the background art platforms, especially for large gas flow-rates.

The term “system” may also be referred to herein as “apparatus.” Various advantages of the exemplary surface platform in terms of cost, foot-print, flow envelope extensibility, and the like, are further described. The exemplary platform can include exemplary components, including the gas/liquid splitter, the combination FWKO/holding tank, and a wet gas flare. The FWKO/holding tank also can be referred to as a two phase separator, i.e., it can separate oil and free water. It is usually a vertical separator used mainly to extract any free water from oil for disposal. Any gas entering the FWKO/holding tank is vented off. The exemplary components are described, for example, in terms of principle of operation, size, and weight, expected performance, and the like.

Referring now to the drawings, wherein like reference numerals designate identical or corresponding parts throughout the several views, and more particularly to FIGS. 9-17 thereof, there is illustrated an exemplary compact fluid disposal system and method for surface well testing, according to the present invention. In FIGS. 9-17, flow-metering and sampling is provided by a multiphase meter 1902 (e.g., a PHASE-TESTER, or Vx TECHNOLOGY available from Schlumberger) located upstream or downstream of a choke manifold 1904 depending on the well head closing pressure. An oil/gas/water stream 1932 is delivered from a flow head 1906. Downstream of the choke 1904, there is provided a gas/liquid splitter (GLSP) system 1908 operating at high pressure (HP) (e.g., up to 1400 psig, and with a minimum additional cost up to 2160 psig). The gas/liquid splitter system 1908 receives flow information 1930 from the multiphase meter 1902 and separates a multiphase stream 1910 from a well into separate streams, including a gas rich stream 1912 sent to a wet gas flare 1914, and a liquid rich stream 1916 sent to a second stage FWKO/holding tank 1918 operating at low pressure (LP) (e.g., 0 to 150 psig) or directly to an oil burner 1920. The second stage 1918 further includes a gas venting output 1927, an output 1922 to a rig tank or pit, e.g., for water to the pit, over board rejection, storage tank or water treatment system, and an output 1924 to a transfer pump 1926 that transfers an oil stream 1928 to the oil burner 1920.

The gas/liquid splitter system 1908 can use the centrifugal forces of the fluid, but in a further exemplary embodiment external power, for example, supplied by an electrical motor, and the like, can be employed. The gas/liquid splitter system 1908 can employ similar principles as the vortex separator of the background art (e.g., a Voraxial separator available from Enviro Voraxial Technology, Inc.) or any other suitable continuous flow separator. However, unlike the vortex separator of the background art, the gas/liquid splitter system 1908 is configured for gas/liquid separation instead of oil/water separation, and advantageously the requirements in terms of separation efficiency can be much lower (e.g., it is possible to accept a non-negligible volume of liquid into the gas exit, and some gas bubbles into the liquid outlet). In addition, the compactness, i.e., relatively small footprint of the exemplary vortex-like system can be slightly undersized, as compared to an application where the separation efficiency has to be close to 100%. A further advantage is the relatively low rotation speed of the impeller that can be employed with the exemplary system, which helps to not induce too much shearing on the liquid to facilitate the later oil/water separation via a gravity effect.

Because of the very short residence time in the exemplary gas/liquid splitter, controllability of the exemplary system should also be achieved. A mixing system, for example, based on the background art flow mixer designs can be placed upstream to dump slugs and prevent the impeller of the GLSP from water hammering effects. In addition, some real time flow-metering data coming from the multiphase meter 1902 can be used to provide an efficient forward control of the employed control valves. Further, except for the very low gas flow rates, the wet gas flare 1914 can be capable of accepting up to 30-40% of liquid, in mass ratio.

The second stage 1918 can be a vertical tank, operating at low pressure (e.g., max 150 psig) for cost reasons, but also to enable degassing of the liquid. The tank 1918 can basically have the same configuration as known double compartment surge tanks. However, the second stage 1918 includes some novel differences in both the design and the mode of operation. For example, a first compartment (e.g., of 50 BBL capacity) is provided and is configured as a tank holder for early cleanup (e.g., mud and dirty fluids in place in the completion and the rate-hole), as shown in FIG. 17. The function of the first compartment is to hold dirty fluids for degassing, before rejection into a rig tank (e.g., offshore) or eventually for burning later on, if the fluid is burnable (e.g., offshore and on-shore). The fluid burn-ability also can be estimated from the multiphase meter in real time measurements for discriminating oil-based mud (OBM) from oil or diesel.

A second compartment (e.g., 50 BBL capacity) is provided and is configured as an oil/water vertical separator or so called free water knock-out (FWKO). The purpose of such a compartment is to extract as clean as possible aqueous fluid (e.g., water or brine) and send the remaining stream 1924, which is mainly oil with less than 25% water, to the oil burner 1920 via the transfer pump 1926. A heating system also is included to raise the liquid temperature and enhance the oil/water separation by reducing the oil viscosity. In addition, an optional electro-coalescer system can be employed (e.g., a background art electrostatic system, such as a VIEC-based system, available from Aibel) to break emulsions and enhance separation and enhance the purity of the extracted water.

Advantageously, as the liquid is being heated in the oil/water separation stage, there is no need for a steam exchanger, which is sometimes needed in a conventional setup, as centrifugal forces applied in the first high pressure stage for gas/liquid pre-separation are enough to drop the gas carry, even in case of high liquid viscosity. However, an issue of gas hydrated formation at the choke manifold level remains, in the case water is present in the effluent. One option is to combine methanol/glycol injection (e.g., traditionally used for shifting of the liquid/solid equilibrium line) with kinetics retardants, and which advantageously does not require a large volume to get a significant effect.

FIGS. 10-12 further detail the exemplary mode of operation of the exemplary surface platform 1900. In FIG. 10 is shown an exemplary flow path at the beginning of the cleanup phase, for example, when the fluids are in place in the completion (e.g., including oil-based mud (OBM), water-based mud (WBM), diesel, fresh water or brine or solid loaded brine). At this stage there is substantially no pressure or very low pressure and possibly large liquid surge flow and even slugs. The effluent might be directly sent to the holding compartment of the second stage 1918 for degassing purposes or it could also flow through the GLSP-HP (Gas/Liquid splitter) system 1908 to first safely handle gas pockets. The gas/liquid separation energy (e.g., via rotation of the impeller) in that case can be fully provided, for example, by an electrical motor.

In FIG. 11 is shown an exemplary flow path after the uploading sequence of fluids in place in the completion and partly the rate-hole. This case is specifically addressing large clean-up for wells in development, for example, when a large volume of water based fluids (e.g., not burnable) have to be recovered at the surface. In this case, the effluent is primarily pre-separated through the gas/liquid splitter (GLSP-HP) system 1908. The liquid rich stream 1916 is then sent to the oil/water separation compartment of the FWKO-LP system 1918 for degassing and oil/water separation. The water (e.g., with water purity basically of the same order of magnitude as water extracted from a conventional horizontal gravity separator) then is extracted from the bottom and disposed in an appropriate manner. The separated oil 1924 (e.g., containing up to 25% of water) then is pumped as an oil stream 1928 by the transfer pump 1926 and burned with the oil burner 1920. The gas rich stream 1912, for example, eventually including a large quantity of liquid is sent to the wet gas flare 1914.

In FIG. 12 is shown the situation of an exemplary stabilized flow-period. At this time, there is normally less than 25% of water in the liquid rich stream 1916 so that the resulting liquid is directly burnable through the oil burner 1920. There is also enough gas and resulting pressure to counteract the back pressure induced by the oil burner 1920. The gas rich stream 1912 can still be sent to the wet gas flare 1914.

The following Table 1 compares the exemplary compact set-up described with reference to FIGS. 9-12 with the background art set-up described with reference to FIG. 2. Table 1 provides a comparison in terms of foot print:

TABLE 1 Background Invention - Art setup with Exemplary Foot Print Background Steam Compact Equipment m × m [m2] Art setup Exchanger Setup Multiphase Meter 1 × 1 [1] X Background art horizontal 5.68 × 2.24 [12.7] X X separator Gas/Liquid Splitter 1.5 × 1.5 [2.25] X Combined FWKO/Tank 2.6 × 2.4 [6.24] X Surge Tank (2 × 50 BBL) 2.6 × 2.4 [6.24] X X Steam Exchanger 6.5 × 2.34 [15.21] X Choke Manifold 1.84 × 1.78 [3.27] X X X Oil Transfer Pump 3.35 × 0.85 [2.84] X X X (PMP-EA 4000 BPD) Total 25.05 m2 40.26 m2 15.6 m2

Based on Table 1, depending on whether or not a steam exchanger is employed with the conventional system (i.e., background art setup), foot-print reduction between about 39% and about 62%, such as between about 40% and about 60% is achieved with the compact setup of the invention.

Thus, the exemplary compact platform includes novel features, including the combination of the multiphase meter 1902, gas/liquid splitter system 1908, the wet gas flare 1914, the combined FWKO/holding tank 1918, and the oil burner 1920. As previously described, the exemplary gas/liquid splitter system 1908 includes a flow mixer, for example, used to minimize the effect of sudden changes of gas volume fraction (GVF) and pressure fluctuations, which typically occurs when the flow is slugging, while also facilitating the system controllability.

The size of the liquid volume (or surge flow) in slug flow conditions is fairly complex to determine, but can be estimated at around 2 BBL. Typically, for example, a 2 BBL flow mixer is enough to prevent a multiphase, multi-stage, centrifuge pump from slug flow. The exemplary embodiments, however, can employ a smaller mixer capacity (e.g., typically 1 BBL), for example, to increase the robustness of the gas/liquid splitter system 1908 against slugs due to low rotation speed and small impeller diameter, to minimize the slug dampening so that the splitter remains controllable under GVF and/or high dynamic flow-rate (e.g., this is related to the speed of control valve actuation downstream of the splitter outlets), and to provide for compactness.

FIG. 13 shows the exemplary G/L splitter 2500 of the gas/liquid splitter system 1908, and which operates on a principle of operation similar to that of the background art vortex-type system. For example, similar to the vortex system, the exemplary G/L splitter 2500 provides for a simple mechanical design with only one part rotating impeller 2502 and with no dynamic vibration induced by solid sticking of a rotating chamber, as used in background art centrifuge systems. In addition, the impeller 2502 design prevents clogging (e.g., due to a large opening area), and similar kind of flow (e.g., light fluid core with some re-circulation) can be achieved as with the background art vortex-type systems. Further, also provided are low electric power consumption by an electric motor 2504, the possibility to add an additional solid outlet if needed, and a light phase discharge pipe with a fixed diameter (e.g., no adjustable weir with complex cinematic need be employed).

Differences from the background art vortex-type system include additional novel features of the G/L splitter 2500, such as a multiphase mixture inlet 2506 that is tangential (e.g., to minimize shearing), the electrical motor 2504 provided in an oil chamber 2508 to obtain a pressure balanced dynamic sealing of a shaft 2510 (e.g., retain pressure between the oil bath surrounding the electrical motor and the separation chamber, which may also be accomplished by a magnetic coupling) to reduce friction, and increase the life time and prevent leaks, the re-use of parts already designed for electrical submersible pumping (ESP, e.g., electrical motor, and impeller), and an automatic gas/liquid interface control of the device. In addition, a feedback control loop to react quickly is provided, including control valve actuation via electric motorization. The G/L splitter 2500 also is configured to separate gas from liquid by employing different impeller and centrifuge forces, as compared to the background art vortex-type system. A low rotation speed is used for the employed diameter (e.g., typically 1800 rpm for a 4″ separation chamber), and with a constant rotation speed to avoid use of a variable frequency drive (VFD) and thus to advantageously reduce size and cost. The G/L splitter 2500 further includes gas rich and liquid rich stream outlets 2512 and 2514, respectively.

FIGS. 14-15 show an exemplary phase-frequency detector (PFD) of the exemplary GLSP-HP system 1908, and including a flow mixer 2606 for providing output stream 2608 to the G/L splitter 2500. In FIGS. 14-15, two motorized control valves 2602 and 2604 are placed downstream of the gas rich outlet 2512 (producing a stream 1912) and the liquid rich outlet 2514 (producing a stream 1916), respectively. In an exemplary embodiment, electrical actuators are employed instead of pneumatic actuators, advantageously, to obtain quick reacting valves. An advanced controller system is provided, for example, based on proportional-integral-derivative (PID) regulation or a Neural network, and using the real time flow-measurements delivered by the Vx meter.

In the exemplary system of FIGS. 14-15, no sub-system for large size particle or metallic debris collection (e.g., typically 1 mm diameter or bigger) need be employed. However, in further exemplary embodiments such a system can be employed to protect the centrifuge from destructive impacts to the impeller, and to prevent clogging of the liquid rich outlet 2514. In such an exemplary embodiment, large damaging solids (e.g., solids above 1 mm diameter) can be captured at the mixer level, by a slight modification of its design, if need be. The exemplary system of FIGS. 14-15 further includes a by-pass system 2702 and the centrifuge 2500 motor housing 2704.

In an exemplary embodiment, the targeted flow-envelope of the exemplary system can be the same or larger than that of the background art systems (e.g., roughly 60 MMSCD & 6000 BLPD or 40 MMSCF & 15,000 BLPD @ 1440 psig).

In a first approximation, one can write:

$G_{force} = \frac{R\; \omega^{2}}{g}$

with

ω the rotation speed in rad/s

R the outer radius (m)

g the gravity acceleration in m/s²

The volume of the separation chamber is defined as:

${Vol}_{chamber} = \frac{\pi \; D^{2}L}{4}$

The volume for the liquid ring and gas core will be approximately and respectively:

${Vol}_{liquid} = {{\frac{{\pi \left( {D^{2} - D_{0}^{2}} \right)}L}{4}\mspace{14mu} {and}\mspace{14mu} {Vol}_{gas}} = \frac{\pi \; D_{0}^{2}L}{4}}$

with D: The inside separation chamber diameter (m)

-   -   D₀: the gas core diameter

The residence time of the liquid and the gas in the separation chamber would respectively be:

$T_{Res}^{Liquid} = {{\frac{{Vol}_{liquid}}{Q_{liquid}}\mspace{14mu} {and}\mspace{14mu} T_{Res}^{Gas}} = \frac{{Vol}_{gas}}{Q_{gas}^{LineCondition}}}$

with Q_(liquid) the liquid volumetric flow-rate (m/s) and Q_(gas) ^(LineCondition) the gas volumetric flow-rate at line conditions (m³/s)

The average liquid droplet size entrained into the outlet gas stream is calculated, as follows (e.g., based on the Stokes law):

$d_{liquid}^{2} = {\frac{0.5D_{0}}{T_{Res}^{Gas}} \cdot \frac{18\mu_{gas}}{\left( {\rho_{liquid} - \rho_{gas}} \right) \cdot g \cdot G_{force}^{{Avg} - {gas}}}}$

The same calculation would apply to estimate the average gas bubble size diameter entrained into the liquid outlet:

$d_{gas}^{2} = {\frac{0.5\left( {D - D_{0}} \right)}{T_{Res}^{Liquid}} \cdot \frac{18\mu_{Liquid}}{\left( {\rho_{liquid} - \rho_{gas}} \right) \cdot g \cdot G_{force}^{{Avg} - {liq}}}}$ ${{with}\mspace{14mu} G_{force}^{{Avg} - {gas}}} = {{\frac{0.25D_{0}\omega^{2}}{g}\mspace{14mu} {and}\mspace{14mu} G_{force}^{{Avg} - {Liquid}}} = \frac{0.25\left( {D - D_{0}} \right)\omega^{2}}{g}}$

With the geometry and fluid properties reported in the two next tables, one can estimate (at 1800 rpm) the size of the gas droplets remaining in the liquid ring and conversely the size of the liquid droplets remaining in the gas core.

TABLE 2 Geometry Centrifuge Internal Diameter D 4 Inch Gas Core diameter D₀ 3 Inch Tube length L 1 Meter

TABLE 3 Fluid properties Liquid Live density 750 Kg/m3 Liquid viscosity 10 Cp Gas specific gravity 0.6 Compressibility factor Z 0.99 Gas Temperature 60 deg C. Gas viscosity 0.02 Cp

TABLE 4 Rotation speed 1800 rpm Qliquid (BLPD) 5000 15000 5000 15000 Qgas (MMSCFD) 10 10 60 60 Pressure (barg) 16 16 100 100 Vliquid (m/s) 2.6 7.8 2.6 7.8 Vgas (m/s) 49.2 49.2 49.7 49.7 Tresidence-liq (sec) 0.38 0.128 0.38 0.128 Tresidence-gas (sec) 0.02 0.02 0.02 0.02 Tresidence-liq eqv 1 g (sec) 62 20 62 20 Tresidence-gas eqv 1 g (sec) 1.4 1.4 1.39 1.4 max gas droplet dia into 71 123 74 128 liquid phase (microns) max liquid droplet dia into 36 36 38 38 gas phase (microns) Vaxial/Vradial for gas 6.8 6.8 6.9 6.9 Vaxial/Vradial for liquid 0.36 1.08 0.36 1.08 Gforce @gas/liquid interface 138

The above droplets sizes are not used to determine the separation efficiency, but rather for enabling one to qualitatively compare the separation efficiency of the invention's exemplary system with the background art horizontal gravity separator. Typically in the background art horizontal separator, the velocity of the liquid and the gas are respectively 0.05 m/s and 0.5 m/s at maximum capacity. With such velocities and the separator geometry and its internal characteristics, one can estimate, for example, by using Stokes law, that the liquid droplet sizes leaving the exemplary separator from the gas outlet would be around 30 microns or less. In the same manner, one can estimate that the size of the gas droplets in the liquid leaving the exemplary separator from the oil outlet would be around 400-500 microns (e.g., under the assumption of a 10 cp oil viscosity) for 1 minute retention time.

Comparing these droplet size numbers, one could determine that the exemplary splitter can be able to better extract gas from liquid (e.g., lower carry-under). On the other hand, the carry-over would be pretty much the same. However, one can expect to have a much larger carry-over because of the flow re-circulation inside the gas core (e.g., as experimentally observed with a similar type of splitter used to separate oil from water). This re-circulation will increase the friction forces at the gas/liquid interface and would probably tend to re-atomize some part of the liquid into the gas core.

To be controllable, the gas/liquid interface needs to stay in between acceptable limits. For example, the radius of the interface has to be kept larger than the radius of the gas core extraction tube and lower than the radius of the separation chamber to avoid sending a large amount of gas into the liquid leg.

FIG. 16 shows an exemplary sensor system 2800 to locate the gas/liquid interface, for example, based on capacitive measurements. In FIG. 16, the exemplary sensor system 2800 includes, at an end of the separation tube 2500, shown in FIG. 13, two annular perforated support plates 2802 supporting capacitive electrodes or armors 2804. The separation tube 2500 includes a separation chamber housing 2806. The housing 2806 and the gas rich stream outlet (also referred to herein as “light phase extraction pipe”) 2512 are used as a support for the electrodes 2804. This creates 4 cylindrical capacitive cells 2808, as shown in FIG. 16.

As shown in FIG. 16, the exemplary sensor system 2800 can be configured with the following exemplary geometrical data, including a length of the capacitor armor 2804 of 50 mm, a gap between R2 and R3 of 5 mm, a gap between R1 and R2 of 3 mm, and a gap between R3 and R4 of 3 mm. Accordingly, one can compute the order of magnitude of capacity to be measured based on the following table, as follows.

TABLE 5 Fluid ε_(r) C_(liq) (pf) C (pf) C_(gas) (pf) Gas 1 — 18 16 Oil 2 110 36 — Salty water 80 4405 1455 —

Assuming that the capacitor C_(liq) will be full of liquid and C_(gas) full of gas (e.g., which can be cross-checked by comparing C_(liq), C_(gas), and C), the gas/liquid interface will be at radius R, so that R3<R<R4, and the following exemplary algorithm can be employed:

Measure C_(liq)

Calculate

$ɛ_{r - {liq}} = {\frac{C_{liq}}{2\pi \; ɛ_{0}}H\; {\ln \left( \frac{R_{4}}{R_{3}} \right)}}$

Measure C_(gas)

Calculate

$ɛ_{r - {gas}} = {\frac{C_{gas}}{2\pi \; ɛ_{0}}H\; {\ln \left( \frac{R_{2}}{R_{1}} \right)}}$

Measure C

Calculate the position of the gas liquid/interface R:

$C = {{\frac{C_{1}C_{2}}{C_{1} + C_{2}}\mspace{14mu} {with}\mspace{14mu} C_{1}} = {{{\frac{2{\pi ɛ}_{0}ɛ_{r - {liq}}H}{\ln \left( \frac{R_{3}}{R} \right)}\&}\mspace{14mu} C_{2}} = \frac{2{\pi ɛ}_{0}ɛ_{r - {gas}}H}{\ln \left( \frac{R}{R_{2}} \right)}}}$

So that:

${\ln \; R} = {\left\lbrack \frac{2{\pi ɛ}_{0}ɛ_{r - {liq}}ɛ_{r - {gas}}H}{C\left( {ɛ_{r - {liq}} - ɛ_{r - {gas}}} \right)} \right\rbrack - \left( {{ɛ_{r - {gas}}\ln \; R_{3}} - {ɛ_{r - {liq}}\ln \; R_{2}}} \right)}$

FIG. 17 further illustrates the combined FWKO/holding tank 1918 used as the exemplary low pressure second stage and using the external geometry, for example, of a background art double compartment (e.g., 2×50 BBL) surge tank. The novel features include the internal design, and the way the vessel capacity is used. In background art operation, there is one compartment (eventually both) used as a holding tank for mud and dirty fluids recovered at the beginning of the clean-up phase. This provides retention time and enables the fluid degassing, which is mandatory in case of rejection into rig tanks, for example. The second compartment is traditionally used for shrinkage and oil flow meter calibration (e.g., using the combined meter factor method), but also as buffer for oil.

In the exemplary compact system of the invention, a first compartment 2902 also is employed for early cleanup fluids collection and degassing. In an exemplary embodiment, a volume of 50 BBL for the first compartment 2902 is sufficient to hold a volume of fluid initially in place in the temporary completion and the rate hole (e.g., 3000 ft long of 3½″ ID tubing and which gives a 35 BBL volume). In extreme cases, where the volume to be recovered is larger than the compartment volume, the fluids can be sent to a rig tank, with the surge tank compartment 2902 being configured to provide a buffer capacity, while still enabling degassing. Accordingly, the first compartment 2902 includes inlet 2904 (e.g., for diesel, OBM, WBM, completion fluid, solids from wellbore cleanup) and outlets 2906 (e.g., for degassed diesel, OBM, WBM, completion fluid, solids from wellbore cleanup for rig tank storage, pit or burning via the oil burner), 2908 (e.g., solid drain for holding tank) and 2910 (e.g., solid drain for FWKO), as shown in FIG. 17.

A second compartment 2912 is configured as a vertical oil/water separator (e.g., free water knock out). The separation stage 2912 enables one to extract the water volume with an oil-in-water content similar to what could be obtained from the background art horizontal separator. The compartment 2912 also can be used as a buffer for oil in the transition zone between the end of the clean-up and the flow period, when the oil flow-rate can be very low and below the minimum flow-rate required by the oil burner 1920. In an exemplary embodiment, in order to optimize the combined oil buffer and oil/water separation compartment 2912 and to unobtrusively monitor liquid levels, there is provided an auto-adjustable floating smart weir 2914. The auto-adjustable floating smart weir 2914 essentially comprises a radial collector connected to a flexible tube/bellow, wherein one end is attached to outlet 2926 of the compartment 2912. The auto-adjustable floating smart weir 2914 is positioned just below the gas/liquid interface, and adjusts automatically regardless of the position of the gas/liquid interface on the oil/water interface. In addition, inlet/outlet 2918 for steam heating (e.g., 10 Barg, 130° C.), bellows 2920, an optional electro-coalescer 2916 (e.g., an electro-static type), outlets 2922 (e.g., for gas venting 1927), 2926 (e.g., for sending oil to the oil burner via the transfer pump 1926), and 2928 (e.g., for sending water to the pit, over board rejection, storage tank or water treatment system), and inlet 2924 (e.g., for liquid (oil/water) from the gas/liquid splitter liquid rich stream 1916) can be provided, as shown in FIG. 17.

In terms of oil/water separation efficiency, the combined oil buffer and oil/water separation compartment 2912 is at least as efficient as the background art horizontal separators. For example, one can use settling theory to compare the oil/water separation capability of the FWKO 2912 with the background art horizontal separator. Specifically, with a density contrast of 200 Kg/m³ between oil and water (e.g., ρ_(oil)=800 Kg/m³ and ρ_(water)=1000 Kg/m³), one can compute the following minimum oil droplet size able to be raised up to the interface, as shown in Table 6.

TABLE 6 Water Flow-rate 2000 4000 6000 Horizontal Separator 150 mic 213 mic 261 mic FWKO 154 mic 218 mic 267 mic

Based on Table 6, one can conclude that the vertical FWKO 2912 can extract water with the same purity as the background art horizontal separator, because although a vertical vessel is less efficient than a horizontal vessel, the increased size of the volume of the vertical vessel is much larger than that of the horizontal vessel.

The exemplary operating mode of the FWKO 2912 can include an oil/water interface (e.g., when present) being maintained constantly at approximately one third of the bottom of the vessel, and with the total liquid level (e.g., oil) varying between a low and a high level (e.g., so as to be able to act as an oil buffer). In addition, the separation compartment 2912 can be heated via a low cost steam circulation coil or heat exchanger 2930 (e.g., employing SS316 ½″ diameter tubing and approximately 25 meter long). This heating capability, advantageously, can reduce the oil viscosity and help the oil/water separation, especially for low oil types (e.g., low API cases).

The following section provides some estimates of the heating capability of the coil 2930. Assuming the following values:

Inlet liquid temperature: T_(fuild) ^(inlet)=40 degC

Steam temperature: T_(steam)=130 degC

Steam pressure: P_(steam)=10 barg

One can compute the temperature increase ΔT of the oil-water mixture heated by the serpentine (e.g., clean tube), as shown in Table 7.

TABLE 7 ΔT (deg C.) Liquid Flow-rate Water Cut (mixture) (BLPD) 95% 75% 50% 25% 1000 57 61 66 72 2000 36 39 44 50 3000 26 28 32 38 4000 20 22 26 30 5000 16 18 21 25

In an exemplary embodiment, the thermal energy transferred from the steam to the liquid is 2.6 MBTU (753 kW), as compared to the heat provided with a conventional steam exchanger of 4.3 MBTU, and while also heating the gas.

As shown in FIG. 17, while not included as standard equipment, but rather as an option (e.g., also not included in the cost estimation above), the heating system 2930 can be combined with the electro-coalescer module 2916 (e.g., a background art electrostatic system) to deal with difficult emulsion cases.

Table 8 below summarizes the functions of the tank in the background art set up and the exemplary invention compact set-up.

TABLE 8 Background Art Setup Exemplary Compact Setup Compartment 1 Holding tank for mud and dirty fluids Holding tank for mud and dirty fluids Mud and dirty fluid degassing Mud and dirty fluid degassing Compartment 2 During Clean-up During Clean-up Holding tank for mud and dirty fluids Liquid degassing Mud and dirty fluid degassing Oil buffer for burning via the oil burner Oil buffer for burning via the oil burner (boosted with a transfer pump) (boosted with a transfer pump) Water extraction from liquid During Flow period Use for combined shrinkage effect and oil meter calibration

Thus, the exemplary embodiments are directed to an exemplary surface testing platform employing a multiphase meter for flow-metering and sampling, and reducing the global foot-print from about 40 to about 60%. The overall estimated cost is significantly of the same order of magnitude as background art platforms based on the horizontal gravity separator. In terms of flow-rate capacity, the exemplary platform is able to handle up to 60 MMSCFD for gas and 15,000 BLPD for liquid at a 1440 psig downstream choke pressure (e.g., a slightly larger operating envelope than a background art platform, in terms of disposal).

The exemplary platform introduces novel components, including a compact gas/liquid splitter based on a vortex technology (e.g., centrifugation via an impeller and separation in a fixed wall chamber), a wet gas flare having a capability to accept up to 30-40% of liquid in mass ratio, and a combined holding tank/FWKO smart system. Gas/liquid pre-separation can be made at a maximum pressure of 1440 psig. However, this maximum pressure can be upgraded to 2160 psig with a reasonable extra cost (e.g., by replacing 600 RF flanges with RTJ Class 900 flanges), boosting the gas capacity by a factor 1.5 (e.g., 90 MMSCFD), and while maintaining the same foot-print.

The exemplary gas/liquid splitter is based on a simplified centrifuge system, having a small diameter and low rotation speed, and thus being more reliable than background art systems based on large cylinders rotating at high speed. In addition, the low rotation speed can minimize the liquid shearing, while not creating very fine dispersed droplets into the continuous phase.

The gas/liquid splitter system has a volume of 1 BBL while providing a low hydrocarbon inventory at high pressure and while improving safety. For high gas rate applications, two gas/liquid splitters can be installed in parallel to handle up to 180 MMSCFD (e.g., in such a case, an 88 mm multiphase meter can be employed).

The exemplary compact platform can extract water with the same oil-in-water content as background art platforms employing a steam exchanger. However, with the heating at choke manifold level being no longer able to ensure help for gas hydrate prevention, in further exemplary embodiments, a combination of methanol/glycol and kinetic retardant injection, instead of heating, can be employed.

An exemplary way to manage the cleanup of this invention, especially the uploading of the fluids in place in the completion and the rate-hole when there is a lack of pressure, will foster the use of this technology in industry. An additional electro-coalescing system can be employed and can significantly improve the purity of the extracted water during the clean-up phase, facilitating the following water polishing step (if needed).

All or a portion of the devices and subsystems of the exemplary embodiments can be conveniently implemented by the preparation of application-specific integrated circuits or by interconnecting an appropriate network of conventional component circuits, as will be appreciated by those skilled in the electrical art(s). Thus, the exemplary embodiments are not limited to any specific combination of hardware circuitry and/or software. In addition, one or more general purpose computer systems, microprocessors, digital signal processors, micro-controllers, and the like, can be employed and programmed according to the teachings of the exemplary embodiments of the present inventions, as will be appreciated by those skilled in the computer and software arts. Appropriate software can be readily prepared by programmers of ordinary skill based on the teachings of the exemplary embodiments, as will be appreciated by those skilled in the software art(s).

While the invention(s) have been described in connection with a number of exemplary embodiments, and implementations, the inventions are not so limited, but rather cover various modifications, and equivalent arrangements, which fall within the purview of the appended claims. 

1. A compact fluid disposal and surface well testing system, the system including: a multiphase meter for flow-metering and sampling of a received oil/gas/water stream and generating flow information for the received oil/gas/water stream; a compact gas/liquid splitter coupled to the multiphase meter and configured for generating a gas rich stream, and a liquid rich stream from the oil/gas/water stream based on the flow information from the multiphase meter; and a free water knock out (FWKO)/holding tank coupled to the compact gas/liquid splitter for receiving the liquid rich stream from the compact gas/liquid splitter and degassing the liquid rich stream and performing oil/water separation on the liquid rich stream.
 2. The system of claim 1, further comprising a wet gas flare coupled to the compact gas/liquid splitter for receiving the gas rich stream from the compact gas/liquid splitter.
 3. The system of claim 2, further comprising an oil burner coupled to the compact gas/liquid splitter and the FWKO/holding tank for receiving the liquid rich stream from the compact gas/liquid splitter or an oil stream from the FWKO/holding tank via a transfer pump therebetween.
 4. The system of claim 3, wherein the FWKO/holding tank includes a gas vent for venting gas that is degassed from the liquid rich stream by the FWKO/holding tank.
 5. The system of claim 4, wherein the FWKO/holding tank includes an output for sending fluids from the liquid rich stream to a rig tank or pit.
 6. The system of claim 3, wherein the FWKO/holding tank further includes an electro-coalescer for enhancing the purity of the water separated from the liquid rich stream.
 7. The system of claim 6, wherein the FWKO/holding tank further includes an auto-adjustable floating smart weir for optimizing the oil/water separation on the liquid rich stream.
 8. The system of claim 5, wherein the system is used for a beginning of a clean up phase of a well and effluent is directly sent to a holding compartment of the FWKO/holding tank for degassing purposes or flows through to the compact gas/liquid splitter to handle gas pockets.
 9. The system of claim 5, wherein the system is used for clean up of a well in development and effluent is pre-separated through the compact gas/liquid splitter, the liquid rich stream is sent to an oil/water separation compartment of the FWKO/holding tank for degassing and oil/water separation, wherein water is extracted from a bottom of the FWKO/holding tank for disposal, and separated oil is pumped and burned with the oil burner, and the gas rich stream is sent to the wet gas flare.
 10. The system of claim 5, wherein the system is used to stabilize flow of a well, wherein the liquid rich stream includes less than 25% of water so that a resulting liquid is directly burnable through the oil burner and the gas rich stream is sent to the wet gas flare.
 11. A method for fluid disposal and surface well testing system, the method including: flow-metering and sampling of a received oil/gas/water stream and generating flow information for the received oil/gas/water stream with a multiphase meter; generating a gas rich stream, and a liquid rich stream from the oil/gas/water stream based on the flow information from the multiphase meter with a compact gas/liquid splitter coupled to the multiphase meter; and receiving the liquid rich stream from the compact gas/liquid splitter and degassing the liquid rich stream and performing oil/water separation on the liquid rich stream with a free water knock out (FWKO)/holding tank coupled to the compact gas/liquid splitter.
 12. The method of claim 11, further comprising receiving the gas rich stream from the compact gas/liquid splitter with a wet gas flare coupled to the compact gas/liquid splitter.
 13. The method of claim 12, further comprising receiving the liquid rich stream from the compact gas/liquid splitter or an oil stream from the FWKO/holding tank via a transfer pump with an oil burner coupled to the compact gas/liquid splitter and the FWKO/holding tank.
 14. The method of claim 13, further comprising venting gas that is degassed from the liquid rich stream with a gas vent of the FWKO/holding tank.
 15. The method of claim 14, further comprising sending fluids from the liquid rich stream to a rig tank or pit with an output of the FWKO/holding tank.
 16. The method of claim 13, further comprising enhancing the purity of the water separated from the liquid rich stream with an electro-coalescer of the FWKO/holding tank.
 17. The method of claim 16, further comprising optimizing the oil/water separation on the liquid rich stream with an auto-adjustable floating smart weir of the FWKO/holding tank.
 18. The method of claim 15, further comprising beginning of a clean up phase of a well, including directly sending effluent to a holding compartment of the FWKO/holding tank for degassing purposes or flowing effluent through to the compact gas/liquid splitter to handle gas pockets.
 19. The method of claim 15, further comprising performing clean up of a well in development, including pre-separating effluent through the compact gas/liquid splitter, sending the liquid rich stream to an oil/water separation compartment of the FWKO/holding tank for degassing and oil/water separation, extracting water from a bottom of the FWKO/holding tank for disposal, pumping separated oil for burning with the oil burner, and sending the gas rich stream to the wet gas flare.
 20. The method of claim 15, further comprising stabilizing flow of a well, wherein the liquid rich stream includes less than 25% of water, including directly burning the resulting liquid through the oil burner, and sending the gas rich stream to the wet gas flare. 